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Solar PV Technical Guidelines for Financiers

Techno-Commercial Risk Mitigation for grid-connected PV systems in Southeast Asia

October 2014

Solar PV Technical Guidelines for Financiers Techno-Commercial Risk Mitigation for grid-connected PV systems in ASEAN

Published by

Deutsche Gesselchaft für Internationale Zusammenarbeit (GIZ) GmbH Renewable Energy Support Programme for ASEAN (ASEAN-RESP) Mott MacDonald, Bangkok Office

Authors:

Iban Vendrell Rudh Korsakul Setta Verojporn Poom Smithtinand Parot Indradesa

Mott MacDonald Contributors:

Phil Napier Moore Duncan Barker

GIZ Contributors:

Arne Schweinfurth Berliana Yusuf

ASEAN-RESP, ASEAN Center for Energy Building, 6th Floor, Jl. H.R.

Rasuna Said, Block X-2 Kav. 7-8, 12950, Jakarta, Indonesia

T +62 (0)21 5278025, F +62 (0)21 5277762, E [email protected]

Mott MacDonald, 19th Floor Chamnan Phenjati Building, 65/159 and

65/162 Rama 9 Road, Huay Kwang, Bangkok 10310, Thailand

T +66 (0)2643 1811 F +66 (0)2643 8638/9 W www.mottmac.com

Disclaimer

Imprint

This document is issued for the party which commissioned it and for specific purposes connected with the above-captioned project only.

We accept no responsibility for the consequences of this document being relied upon by any other party, or being used for any other purpose, or containing any error or omission which is due to an error or omission in data supplied to us by other parties.

This document contains proprietary intellectual property. It should not be distributed to other parties without consent from Mott MacDonald and GIZ ASEAN-RESP.


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Chapter Title Page

Executive Summary i

1 Introduction 1

1.1 Context and objectives _______________________________________________________________ 1 1.2 Bankers workshop __________________________________________________________________ 2 1.3 Renewable Energy Support Programme for ASEAN (ASEAN-RESP) ___________________________ 3 1.4 Mott MacDonald ____________________________________________________________________ 3 1.5 Guideline structure __________________________________________________________________ 4

2 Introduction to solar PV systems 5

2.1 Solar PV systems ___________________________________________________________________ 5 2.1.1 PV module ________________________________________________________________________ 6 2.1.2 Inverter __________________________________________________________________________ 10 2.1.3 Foundation and mounting structures ___________________________________________________ 12 2.1.4 Transformer ______________________________________________________________________ 14 2.1.5 Electrical cables ___________________________________________________________________ 15 2.1.6 Transmission line __________________________________________________________________ 16 2.1.7 Monitoring system _________________________________________________________________ 16 2.2 Resource potential and revenue calculation ______________________________________________ 17 2.2.1 Solar irradiance ___________________________________________________________________ 17 2.2.2 Ambient Temperature _______________________________________________________________ 19 2.2.3 Performance Ratio _________________________________________________________________ 20 2.3 Cost structure of a solar PV project in the region __________________________________________ 27

3 Risk management and mitigation under project finance 28

4 Due diligence checklists 29

4.1 Overview ________________________________________________________________________ 29 4.2 Key technology risks________________________________________________________________ 29 4.3 Design and construction risks _________________________________________________________ 30 4.4 Performance projection risks _________________________________________________________ 32 4.5 Operation risks ____________________________________________________________________ 33 4.6 Contractual risks ___________________________________________________________________ 34

Appendices 36

Appendix A. Detailed Annual Energy Output Calculation Derivation _____________________________________ 37

Glossary 38

Contents


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Among the countries of the Association of Southeast Asian Nations (ASEAN),

there is a significant potential for the use of Renewable Energy (RE), which draws

an increasing interest among the ASEAN Member States (AMS).

In 2012 the Renewable Energy Support Programme for ASEAN (ASEAN-RESP),

jointly implemented by the ASEAN Centre for Energy (ACE) and Deutsche

Gesellschaft für Internationale Zusammenarbeit (GIZ), conducted a

comprehensive survey on prevalent success factors and remaining barriers for

“bankable” RE projects in chosen AMS.

ASEAN-RESP was tasked to identify examples of good practice of private

investment in renewable energy projects and to develop “ASEAN RE Lending

Guidelines” for banks/investors (henceforth called “the Lending Guidelines”). The

need for such guidelines, especially for solar Photovoltaic (PV) investments, was

confirmed by banks from the AMS at several occasions.

The Technical Guidelines in this report intend to give a summary of international

good practice for solar PV projects developed under non-recourse project finance,

oriented to include projects financed in ASEAN. Each project needs to be

assessed individually and investors’ views on the risks they are prepared to take

on vary. Also, as technology evolves and is demonstrated, good practice

guidelines change on experience needed. Nevertheless, it is hoped that these

technical guidelines will be a useful tool for the evaluation and development of

projects – which may lead to increased activities in the region and increased use

of green energy in ASEAN.

The Technical Guidelines highlight some key technical items through the project

cycle and summarise common current views on bankability, taking regional

specificities (climate, market size, etc.) into account. The Guidelines have been

drafted with banks and similar investors in the ASEAN member states in mind.

Mott MacDonald has prepared the Technical Guidelines, drawing on its extensive

PV project experience as the leading international consultancy for solar PV power

in Southeast Asia, and incorporating Lender community feedback from a regional

Banker’s focus group discussion held jointly with ASEAN-RESP in May 2014.

Executive Summary


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1

1.1 Context and objectives

Renewable energy (RE) is an important element in a diversified and

sustainable energy mix, which increases energy security and

contributes to the mitigation of climate change by reducing the CO2

emissions. Among the countries of the Association of Southeast Asian

Nations (ASEAN), there is a significant potential for the use of RE,

which draws an increasing interest among the ASEAN Member States

(AMS).

Over the last decade, many member states introduced regulatory

frameworks, including financial incentives, in order to stimulate the RE

market and to tap the huge potential in the region. Despite those

efforts, the large-scale deployment of RE technologies for power

generation is still facing barriers. One of the reasons is the fact that

private investments in the RE sector are relatively scarce and often

made on a case-to-case basis.

Nevertheless, many success stories of private investment in RE

projects in the ASEAN region exist and important lessons can be learnt

in order to push the regional RE market from the inception to the take-

off phase. In 2012 the Renewable Energy Support Programme for

ASEAN (ASEAN-RESP), jointly implemented by the ASEAN Centre for

Energy (ACE) and Deutsche Gesellschaft für Internationale

Zusammenarbeit (GIZ), conducted a comprehensive survey on

prevalent success factors and remaining barriers for “bankable” RE

projects in chosen AMS. As an outcome the “ASEAN Guideline on

Renewable Energy Support Mechanisms for Bankable Projects” (Policy

Guidelines) presents effective policy approaches and support

mechanisms to improve framework conditions for positive investment

decisions in the RE sector.

Despite the Policy Guidelines, large-scale investments are still missing.

For this reason, ASEAN-RESP was tasked by the ASEAN Specialized

Bodies for Energy to identify good practices of private investment in

renewable energy projects and to develop “ASEAN RE Lending

Guidelines” for banks/investors (henceforth called “the Lending

Guidelines”). The need for such guidelines, especially for solar

Photovoltaic (PV) investments, was confirmed by banks from the AMS

at several occasions. The Guidelines as presented here are intended

to provide techno-commercial guidance of international good practice

for solar PV projects developed under non-recourse project finance and

to include lessons learnt from project examples financed in ASEAN. It

is envisaged to become a practice-oriented tool which helps investors in

their risk assessment of potential RE projects. In the long run, with

1 Introduction



2

effective dissemination, it is expected that the Lending Guidelines will

cause increased investment activities in the region and in effect

increased use of green energy in ASEAN.

The Lending Guidelines highlight common (technical) risks throughout

the project cycle and offer advice on how to manage and/or mitigate

them, taking regional specificities (climate, market size, etc.) into

account. The target group of the guidelines are local banks and

investors in the ASEAN member states, however, investors in other RE

markets can also benefit from the guidelines.

Each project needs to be assessed individually to check the particular

context, components and structure. Also, investors have different views

on which risks are manageable. These Lending Guidelines do not

replace the need for an independent technical advisor during the project

finance process and it is recommended that Lenders use the services

of an experienced technical consultant to assist them and, in particular,

to identify the project specific risks and issues that need to be

addressed.

1.2 Bankers workshop

In order to support the identification of good practices/needs

assessment among the target group (bankers/investors) in the AMS, a

regional focus group discussion for bankers was conducted jointly by

Mott MacDonald and ASEAN-RESP in order to: (i) present the current

practices and guidelines of banks with experience in solar PV and other

Renewable Energy (RE) technologies (on-shore wind) investments

(both international and regional) and (ii) identify key issues to be

addressed by the Lending Guidelines.

The regional focus group discussion on “RE Lending Guidelines for

Bankers in the ASEAN” was held in Bangkok, Thailand, on 22-23 May

2014. Targeted participants were bankers from ASEAN Member

States, particularly countries with high potential of solar PV power

and/or wind power such as Indonesia, Malaysia, Philippines, Thailand

and Vietnam. Representatives from NGOs and consulting/advisory

companies also joined the workshop.

The workshop served as a starting point for developing RE Lending

Guidelines for bankers in the ASEAN region, with a particular focus on

PV projects. The main topics discussed in the workshop included both

technical and commercial aspects, focusing on the risk assessment of

solar PV and wind power projects. The issues identified in the

workshop are used as the basis for determining structure and content of



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the Lending Guidelines presented in this report which focus on techno-

commercial risk mitigation in solar PV project financing.

1.3 Renewable Energy Support Programme for ASEAN

(ASEAN-RESP)

The Renewable Energy Support Programme for ASEAN (ASEAN-

RESP) is a jointly implemented project by the ASEAN Centre for

Energy (ACE) and the Deutsche Gesellschaft für Internationale

Zusammenarbeit (GIZ) GmbH. The programme supports the regional

exchange to improve framework conditions for renewable energies in

ASEAN. By implementing its activities and working towards the overall

objective, the project supports the realization of the APAEC and

encourages ACE and the ASEAN member states in working towards a

greener region.

As a regional project ASEAN-RESP implements activities with

relevance for all ASEAN member countries, following its guiding

principle ‘learning from each other’. Through its close collaboration with

ACE and other relevant regional institutions, the project supports the

ASEAN member states in better making use of existing policies and

experiences, transfering knowledge and exchanging regional expertise.

1.4 Mott MacDonald

Mott MacDonald is a global management, engineering and

development consultancy and a top firm in power. As the leading

international consultancy for solar power in Southeast Asia, we draw

from a wide resource pool of in-house expertise covering all aspects of

the engineering and technology sectors, with specialists in power

markets, regulation, policy, electrical networks, civil design, PV module

manufacturing, solar resource assessment and PV plant development.

The Mott MacDonald engineers contributing to the authorship of these

Lending Guidelines have supported the majority of operating solar PV

capacity within ASEAN to date, comprising more than 900 MWp across

140 projects, as well as a further 500 MWp of projects under

development in the region. We have supported domestic Lenders with

proposed project finance for PV projects in Thailand, the Philippines

and Malaysia. The Mott MacDonald team has published a range of

technical papers regarding layout design, technology selection and

performance assessment for solar PV plants in the Asia Pacific region1.

1 Including for example:



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1.5 Guideline structure

This guideline document is structured into the following sections:

� Section 2, Introduction to solar PV systems, provides a brief

overview of main components and technologies of a PV system,

system performance and cost considerations serving as a general

glossary and guidance to contextualize subsequent sections.

� Section 3, Risk management and mitigation, briefly explains risk

management and risk mitigation under the context of non-recourse

project finance.

� Section 4, Due diligence checklist, presents a techno-commercial

risk assessment highlighting common technical risks throughout

the project cycle and offers advice on how to manage and/or

mitigate them. It should be noted that no environmental and

permitting risks, which are mostly country-specific, are included in

these Lending Guidelines.

(i) “Lessons Learned from Solar PV Project Development in Japan: Optimal Array Design for Complex Sites”, Renewable Energy World Asia, Kuala Lumpur, September 2014. Smithtinand, P.; Cherdsanguan, N.

(ii) “In-field performance of a polycrystalline versus a thin-film solar PV plant in Southeast Asia”, Photovoltaics International - 22nd Edition, 18 December 2013. Verojporn, S.; Napier-Moore, PA.

(iii) “Gaining confidence in PV module performance through laboratory testing, factory audit and analysis of in-field data”, Renewable Energy World Asia, Bangkok, October 2012. Napier-Moore, PA; Verojporn, S.

(iv) “Concentrating solar power compared with flat-plate collectors: Why South-East Asia's largest solar plant uses thin film PV technology”, Energy, Volume 164 May, Issue EN2, Proceedings of the Institution of Civil Engineers, May 2011, Napier-Moore, PA.



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2.1 Solar PV systems

In a grid connected solar PV power plant, the most distinctive

technology items are solar modules and inverters. The modules will

harvest the solar energy (solar irradiance) and convert it into direct

current (DC) power. The inverters will be designed to work under the

variable power output of the modules, to convert the DC power into

alternating current (AC) power, for which voltage will be then stepped-

up through transformer(s) in order to deliver useful AC power to the

grid.

Solar PV systems can be small-scale building mounted systems that

either supply power to building demands or inject power to the grid

(rooftop solar PV systems), or large-scale ground mounted grid

connected solar PV systems. Although the Lending Guidelines are

based on Mott MacDonald’s experience on large-scale ground mounted

grid connected solar PV systems (as it is necessary to achieve a

minimum of scale and investment for lenders to engage in non-recourse

project finance); most of the points outlined in the Lending Guidelines

are also applicable to rooftop solar PV systems, in case these comprise

large commercial developments or can be bundled to meet the

minimum size for non-recourse project finance.

Typically, the main components of a grid-connected PV system include:

� PV module;

� Inverter;

� Mounting structure (fixed or tracking);

� Transformer;

� Electrical cable;

� Protection systems (e.g. short current, over voltage and lightning

protection);

� Transmission line; and

� Monitoring system and weather station.

Figure 2.1 provides a simplified diagrammatic representation of a solar

PV system, including how selected main components typically connect

to one another.

2 Introduction to solar PV systems



6

Figure 2.1: Typical Solar PV System

Source: Mott MacDonald

2.1.1 PV module

The PV module can be considered as the most critical component in a

solar PV system. A PV module is a packaged product comprising an

electrically connected assembly of solar cells. DC electricity is

generated via the photo-electric effect using irradiance energy from the

sun to create an electric current through the PV module.

A commercial PV module is typically rated by its DC output power at an

approximate range of 100 – 320 watts (W) with a nominal efficiency

under standard test conditions (STC) typically ranging from 8% – 20%

depending on technology and quality. STC conditions are further

described in Section 2.2.3.1 below.

Generally, solar PV module technologies can be classified as follows:

� Crystalline PV, including mono-crystalline and poly-crystalline; and

� Thin-film PV, including amorphous silicon (a-Si), copper indium

gallium selenide (CIGS), and cadmium telluride (CdTe).

2.1.1.1 Crystalline and thin-film PV modules

Crystalline silicon solar technology (Figure 2.2) was the first type of PV

technology to be widely commercialised. Based on the silicon crystal

type and crystal size, crystalline cells are categorised as

monocrystalline and poly-crystalline. Typically, a monocrystalline PV



7

module has a higher nominal efficiency of up to 20% while a poly-

crystalline PV module has a nominal efficiency ranging from

approximately 14% to 18%.

Figure 2.2: Crystalline PV module Figure 2.3: Thin-film PV module

Thin-film technology (Figure 2.3) comprises a thin semiconductor layer

deposited on a low cost flexible substrate. The lower use of silicon or

other semiconductor material can reduce the manufacturing costs of the

module considerably but typically leads to lower efficiency (7 to 11%)

compared to crystalline silicon technology.

Technology selection is driven by project and site features and

associated techno-commercial aspects. Key variables for decision

making are, for example, as follows:

Technical aspects

� Nominal efficiency (STC);

� Performance affected by site temperature conditions; and

� Performance affected by site irradiance condition.

Commercial aspects

� Choices of PV module manufacturers; and

� Costs of PV modules.

The pros and cons between crystalline and thin-film PV module

technology, particularly for the Southeast Asia (SEA) region, are

highlighted in Table 2.1.



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Table 2.1: Crystalline and Thin-film PV module technology comparison

Item Description Crystalline Thin-film

Technical aspects

Nominal Efficiency (at STC)

Nominal efficiency (at STC) has a direct impact on required land area for solar PV development.

Higher nominal efficiency of PV modules installed leads to lower land area requirements at a given plant output capacity.

Relatively more suitable for sites with limited land area due to its higher nominal efficiency (STC).

Suitable for projects with no significant land constraints (e.g. low cost to purchase land, or where peak output rather than available area is the main limiting factor).

The cost to purchase additional land can offset the cost benefit of thin-film technology.

Temperature conditions Ambient temperature within the SEA region is usually high, which critically impacts on the PV modules performance.

Different PV module technologies perform differently at high temperature conditions.

Higher power loss compared to thin-film PV module technology under high temperature conditions.

In most cases, lower power loss compared to PV crystalline technology in high temperature conditions.

Irradiance condition PV module efficiency varies with irradiance condition (e.g. efficiency is lower at 200 W/m2 irradiance compared to STC irradiance condition at 1000 W/m2).

Poorer capacity of converting low irradiance into useful energy output compared to thin-film PV due to light absorbing characteristics.

Typically uses low irradiance resource more effectively compared to crystalline PV modules, especially relevant in a tropical climate.

Commercial aspects

Manufacturer options The more manufacturer options, the more flexibility to select a solar PV technology that suits project needs. This again adds flexibility when module replacements or technology/manufacturer modifications.

More manufacturer options as the technology has higher track record and is more widely commercialised.

Lesser manufacturer options compared to crystalline PV module manufacturers.

Costs Cost of the PV module significantly drives the cost of a solar PV system, typically accounting for 30 – 40% of capital expenditure (CAPEX).

Commercialised crystalline PV module cost in 2014 ranges approximately between 0.6 – 0.8 USD/Wp.

Commercialised thin-film PV module cost in 2014 ranges approximately between 0.4 – 0.5 USD/Wp.

Although thin-film PV modules generally perform better for the SEA

climate conditions, nonetheless because of their higher land

requirements and recent diminished cost differential compared to PV

crystalline technologies, their popularity in this region has reduced in

the last few years. Technology choice should however be considered

on a project by project basis, based on evaluation of the specific

aforementioned techno-commercial aspects.



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2.1.1.2 PV module testing and certification

Table 2.2 presents typical PV module testing and certifications to

international standards, including both:

� Obligatory certifications, which are usually considered a minimum

requirement for use of a PV module under project financing; and

� Optional certifications and PV module tests that may also apply

depending on the specific project location or design.

Table 2.2: Typical PV Module Certifications and Tests

Subject of Certifications Standards

Obligatory Certifications

Design qualification and type approval

- Crystalline silicon terrestrial photovoltaic modules or

- Thin-film terrestrial photovoltaic modules

IEC 61215:2005

IEC 61646:2008

Photovoltaic (PV) module safety qualification;

Part 1: Requirements for constructions

Part 2: Requirements for testing

IEC 61730

Part 1 and Part 2

Safety qualification of PV module Safety class II

Optional Certifications / Tests

Compliance with EU legislation CE

Standard for flat-plate photovoltaic modules and panels UL 1703

Environmental certification PV Cycle

Ammonia testing IEC 62716

Salt mist corrosion test (usually to severity level 1 or 6) IEC 61701

Potential-induced degradation (PID) test IEC 62804

‘System voltage durability test for crystalline silicon

modules’

Damp heat test (extended) Test under IEC 61215 standard

Certifications of Module Manufacturer’s Facilities

Quality management systems ISO 9001:2008

General requirements for the competence of testing and calibration laboratories

ISO 17025:2005

Environmental management systems ISO 14001:2004

Design and manufacturing of solar modules BS OHSAS 18001:2007

Manufacturing of solar power devices for the automotive industry - with product design and development -

ISO 16949:2009



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2.1.2 Inverter

As the grid network usually carries AC electricity, the DC power

generated by the solar PV modules must be converted for delivery to

the grid network in the form of AC power. The inverter is designed to

work under variable power output conditions of PV modules in order to

convert DC power to AC power.

2.1.2.1 String and central inverters

The global market for grid-tied PV inverter supply is more concentrated

than for PV modules. Typically, grid connected PV inverters can be

broadly classified into two categories (see Figure 2.4 and Figure 2.5

below):

� String-inverter (typically < 50kW AC power output); and

� Central-inverter (in the usual range of 100 kW to 1,200 kW AC

power output).

Figure 2.4: Central inverter Figure 2.5: String inverter

Key parameters for technology comparison are defined as follows and

further explained below:

� Inverter efficiency;

� Installation area requirements; and

� Maintenance requirements.

In addition to technological differences, string and central inverters

usually have a different cost profile, with a different inverter installed

cost and requiring differing lengths of DC and AC cables to be installed.



11

Inverter Efficiency

The inverter efficiency is mainly dependent on associated losses

related to:

� DC to AC conversion;

� Maximum Power Point Tracking; and

� Auxiliary power consumption.

Maximum Power Point Tracking (MPPT) is essential in any PV system

as the power output changes under changing environmental conditions.

In order to maximize the power output, the MPP tracker adjusts the

module voltage to reach maximum power output under given

conditions.

Typically, central inverter technology is more efficient to convert DC-AC

compared to string inverter. Conversely, string inverters are more

efficient for Maximum Power Point Tracking, in case of variable and

dynamic irradiation conditions across the PV arrays. Central inverters

will generally also have higher auxiliary power demands in the SEA

region, in particular for cooling of the inverter enclosure. Considering

all factors central inverter technology is generally more efficient

compared to string inverters as losses in DC to AC conversion is the

major factor driving the overall inverter efficiency. Generally central

inverter technology is found to be more economical when compared to

string inverters, especially for larger PV systems. However, the choice

of technology should be justified on a project by project basis through a

project cost-benefit analysis, also bearing in mind the additional factors

discussed below.

Installation area requirement

Central inverters are typically installed in a concrete building or to a

lesser extent in container boxes which require a certain amount of site

space. String inverters can be installed underneath PV modules and

therefore may not require any additional area, which is beneficial under

land/area constrained scenarios, including for some rooftop solar PV

plants.

Maintenance requirement

For the same amount of AC power output capacity, the number of string

inverters required is higher to central inverter. For equivalent unit

failure rates, lower maintenance requirements are therefore required for

central inverters compared to string inverters. Conversely, a single

string inverter outage has a much less significant impact on the overall



12

plant output, and outages due to string inverter failures can be quickly

rectified, by simply replacing a failed unit with an on-site spare while

awaiting repair.

String inverters are therefore often favored for smaller projects up to

several megawatts capacity and remote locations where maintenance

response time from the inverter supplier is expected to be slow.

2.1.2.2 Inverter testing and certification

Table 2.3 presents typical inverter certifications to international

standards, including German VDE standards that are widely referenced

internationally. Inverters manufactured for international markets will

often possess such certification, which provides reassurance that the

inverter technical characteristics can meet typical quality, safety and

grid code requirements. Nonetheless, we note that compliance with

national grid code requirements for the project site location is the key

requirement for inverter testing, rather than international code

compliance. This contrasts with PV module certifications, where

international codes are usually the primary reference.

Table 2.3: Typical Inverter Certifications

Subject of Certifications Certifications

Low voltage Directive (Electronic equipment designed for use within certain voltage limits)

2006/95/EC

EN 50178:1997

Electromagnetic compatibility (EMC)

2004/108/EC

EN 61000-6-2:2005

EN 61000-6-4:2007

EN 61000-3-12:2004

Compliance to EU legislation CE

Photovoltaic (PV) systems. Characteristics of the utility interface

IEC 61727:2004

Safety of power converters for use in photovoltaic power systems

EN 62109-1:2010

Grid Management VDE-AR-N 4105/08.11

DIN VDE V 0124-100/07.12

2.1.3 Foundation and mounting structures

Foundation and mounting structures should be designed to support the

solar PV module positioning for the entire project life (e.g. typically 20 –

25 years).

Mounting structures can be either fixed or tracking systems, with the

latter changing the module orientation to track the positioning of the sun



13

(either through a one or two axis rotation). Fixed systems are lower

cost, so the energy production gains resulting from tracking systems

should be considered in a cost-benefit analysis on a project by project

basis. In general, tracking systems will result in a more significant

benefit at extreme latitudes, so are less relevant for application in SEA

than in temperate regions of the world, though may still be cost-

effective.

In terms of foundations, piled foundations (Figure 2.6) for mounting

structures are most common, although depending on site soil conditions

and local material supply costs, use of concrete spread footings (Figure

2.7) may also be applicable.

Figure 2.6: Piled foundation Figure 2.7: Spread footing

For piled foundations, piled beams, screw piles, or cast concrete,pile

foundations are commonly used in solar PV systems depending on the

soil conditions of the site, established through preliminary geotechnical

surveys.

With the exception of concrete foundation elements, all other

foundations and mounting structures typically use galvanized steel, for

adequate corrosion resistance. Galvanization thickness will depend on

the specific site climate condition. Aluminum mounting structures are

also used for some plants, usually with stainless steel fittings.

Mounting structure and foundation suppliers are often specialized

international firms, however domestic steel fabricators have also

sometimes been successfully used for projects within SEA.



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2.1.4 Transformer

The solar PV system will generate electrical power at a low voltage

level (LV), similar to that used for domestic power supply. In order to

step-up this low level voltage to adequate grid voltage level,

transformers are used. A transformer is an electrical device that

transforms electrical energy (stepping up or stepping down the voltage)

between two or more circuits through the principle of electromagnetic

induction.

2.1.4.1 Transformer losses

Transformer losses can be expected during day and night time, and the

two major loss types are generally categorized as follows:

� Load loss (“copper” loss); and

� No-load loss (“iron” loss).

During the day time, when the transformer is in-operation, the ohmic

loss in the copper windings of the transformer is the predominant loss.

No-load losses, which relate to energisation of the iron transformer

core, can be also expected during day-time and night-time. Such no-

load losses predominate at night-time or when a plant is not in

operation but remains connected to the grid and consumes power from

the grid. Such losses could be avoided by opening the MV/HV breaker

every evening, if permitted by the grid operator and plant electrical

configuration.

2.1.4.2 Transformation stages

As mentioned, transformers are used to step-up the voltage level of the

plant to the grid voltage level. However, some projects may require

several transformer stages (e.g. two stages) in order to achieve grid

voltage level.

Typically, if the plant will be connected to the grid with medium voltage

(MV) (e.g. 22 kV or 33 kV) a single transformation stage is used for the

project. However, when connecting to the grid at high voltage (HV)

(e.g. 69 kV or 115 kV), use of two transformation stages is common.

Multiple transformation stages will lead to higher transformer losses for

the projects, but may nonetheless be useful to optimize the overall cost

and cabling losses of the project.



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2.1.4.3 Transformer types

Transformers can be broadly classified into two types which are ‘dry’

and ‘liquid’ type transformers, describing the transformer cooling and

insulation mechanism. The ‘liquid’ type generally uses mineral oil to

insulate and cool the transformer windings. Generally, the pros and

cons for these two types of transformer are:

Dry type

� Higher cost

� Lower maintenance

� Indoor/Outdoor use

Liquid type

� Lower cost

� Higher maintenance

� Outdoor use

One of the most common types of low capacity transformer which are

being used for solar PV plants within the region is the hermitical sealed

oil transformer. This type of transformer requires lower maintenance

than a standard oil-type transformer (which is open to moisture ingress

with oil heating/cooling). For oil-type main HV transformers used in

large solar PV plants, forced circulation of the air using fans to cool the

internal oil may also be used in some cases, and increases transformer

capacity.

It is common to source domestically manufactured transformers for

solar PV projects. However, it is expected that the transformer will be

made to IEC 60076 standard, are designed suitably for site conditions

(e.g. tropical conditions for SEA) with a two to three year defect

warranty period. Transformer supplier facilities should preferably be

certified to ISO 9001 (design and development and manufacture of

distribution transformers and power transformers) and ISO 14001

(manufacture of distribution transformers and power transformers).

Transformer track-record from the supplier should preferably include

reference projects within the same region, and use within PV projects.

2.1.5 Electrical cables

Electrical power generated in a solar PV system is transmitted between

each series component via electrical cables. Selection of cable size,

type and installation method depends on the design and configuration



16

of the plant. Undersized DC or AC cables in any one of the multiple

series connections between the PV module and grid connection point

can significantly affect overall plant losses, and, in the worst case,

cause cable fire.

Copper cable is used for LV conductors in order to minimize cable

losses. Copper or aluminum cable is used for medium voltage (MV)

cables.

One of the specific types of cable which are commonly used in solar PV

projects is ‘solar cable’. In brief, solar cables are used for cabling of the

solar PV modules through inverters, and are designed to tolerate a wide

range of temperature, various environmental conditions, and provide

resistance to UV radiation in order to be suitable for typical outdoor

solar PV plants conditions.

One key design issue throughout the PV plant is that cable insulation

must be appropriately selected and be able to withstand thermal and

mechanical loads. Cable insulation materials must be appropriately

resistant to weathering, UV radiation, and abrasion. Poor cable

insulation may lead to current leakage, usually resulting in a ground

fault, which in turn lowers the available operating hours of the plant.

Although cables may be selected properly, poor construction quality

could also result in cable insulation damage impacting on plant

availability.

2.1.6 Transmission line

Solar PV systems can be located in remote areas without access to

existing transmission lines. In this case new transmission lines must be

constructed in order to transmit electrical power from the plant to the

grid. Responsibility of construction typically rests with the grid owner,

although cost for new transmission will be subject to agreement

between the project company and the grid owner, and will often be

borne by the project.

2.1.7 Monitoring system

The monitoring system is a fundamental part of the solar PV plant as it

allows the owners and operators to monitor the real performance of the

plant against the expected performance. The real performance of the

plant is monitored based on the output power from the inverters. The

expected performance of the plant for the same period is calculated

based on the actual weather conditions at the site location including

irradiation, temperature of the solar cells and ambient temperature.



17

2.2 Resource potential and revenue calculation

Calculation of expected energy production and related revenue from

electricity sales is key for any power generation project investment.

The energy yield assessment performed for any solar PV plant is

intended to provide a best-estimate of the expected energy output of

the plant, which in turn can be used in the project financial model to

assess financial performance.

The key parameters for energy yield assessment are:

� Solar irradiance as a critical and sensitive modelling input;

� Ambient temperature as a modelling input; and

� Performance Ratio (PR) calculation.

2.2.1 Solar irradiance

The energy production of a solar PV plant depends on the incident

amount of irradiance available on its solar PV modules. Irradiance, or

sunlight, is a measure of the electromagnetic radiation hitting a surface

of the solar PV modules. Irradiance varies throughout the course of a

day as well as seasonally. The irradiance is usually averaged over a

day, month or year to then predict the Performance Ratio (PR) and

energy yield of the plant.

The SEA region has relatively scarce measurements of solar irradiation

levels, compared with more established solar PV markets in Europe

and the US; techniques to reliably estimate irradiation given such data

scarcity are also not yet commonplace in the global solar PV industry.

In our experience, it is currently not uncommon for estimates of

irradiation resource in SEA to be inaccurate and insufficiently rigorous,

and for significant overestimates of energy yield to result.

For a Project Lender, robust selection of solar irradiance data is

therefore a critical and sensitive input to the financial model, which

drives the ability of the project to meet debt service obligations.

2.2.1.1 Solar irradiance data considerations

Typically, more than one source of irradiation is used for comparison

prior to evaluation of energy production in solar systems. Irradiance at a

given proposed site location can be estimated based on:



18

� Ground-based measurements or irradiance at nearby weather

stations, made using a pyranometer; or

� Satellite-derived estimates of irradiance, either from public sources

or specialised private data providers.

Irradiance data is usually recorded as Global Horizontal Irradiance

(GHI), which is defined as the amount of sunlight that falls on a 1 m2

horizontal area measured in kWh/m2. Irradiance at the inclined plane

can also be measured, or else calculated from the horizontal values.

When assessing irradiation data for a specific location, it is

recommended to have long-term data (10 to 20 years) to be able to

establish a reliable average value with a clear assessment of its

variation (maximum and standard) over the Project life.

Available public irradiance sources in the region (e.g. MeteoNorm,

National Meteorological Agencies, NASA SSE) and data from solar

irradiance data providers are commonly used for energy yield

assessment for solar PV systems. The annual average GHI in SEA

approximately ranges between 1,600 – 1,800 kWh/m2/year.

Ground-measured irradiance data

Use of ground-based irradiance measurements weather stations to

estimate irradiance data at a given site is generally preferable,

providing that the data quality can be established and that the reference

weather station is located in close proximity to the solar PV plant site

(e.g. within 25 km radius), as at this proximity the risk of variability in

local conditions is largely mitigated. To ensure that irradiance data

from ground weather stations is reliable, it is important to understand

the methodology applied to obtain the data including:

� Type of instrumentation and associated data logging equipment

used;

� Operation and maintenance scheme of such instrumentation,

including sensor cleaning and instrument recalibration;

� Resolution of data logging;

� Methodology applied when there are data gaps;

� Surrounding condition of the weather station (e.g. shading on

pyranometer may lead to negative-bias of data obtained); and

� Quality control approach used for the data generated.

In some cases, ground meteorological stations are developed at the

project site to obtain irradiance data and other environmental data at

the specific site location, usually as short-term data (e.g. 1 – 2 years).



19

If the methodology applied to obtain irradiance data is considered

satisfactory, the data can be correlated against a representative long-

term data source to reduce the risk of local variability.

Satellite-derived irradiance data

In general, satellite-derived irradiation data sets comprise

extrapolations from satellite photography combined with supporting

satellite- or ground-based measurements and assumptions regarding

the composition of the atmosphere and geographical inputs.

As satellite-based irradiance data is derived through modelling and

assumptions, uncertainties of irradiance data from satellite-based data

are generally higher compared to ground-measured data, although the

relative accuracy varies with each location and region, depending on

both the quality of ground measurements and accuracy of the satellite-

based models.

When using satellite-based irradiance data, it is strongly recommended

that the data provider shows evidence that the irradiance data has been

validated with irradiance derived from ground meteorological stations

located nearby the specific site location. Because uncertainties of

satellite-based data inherently vary by location, due for example to

relatively low spatial resolution of the atmospheric inputs used in the

modelling, data validation is important quantify uncertainties. Accurate

ground measurements may also be used as the basis for tuning of the

satellite-based models, to improve overall accuracy in a given region

2.2.2 Ambient Temperature

Ambient temperature is another important input for energy yield

assessment, as PV module performance is highly dependent on this

parameter.

Similar to solar irradiance, ambient temperature data can be obtained

from ground-measurement or satellite-based sources depending on

availability and quality of such data. It is typically recommended to

have 10 – 20 years length of data to reduce inter-annual variability.

Ground based measurements of ambient temperature are much more

commonplace than for ground based measurements of irradiation, and

it is usually possible to obtain several different data sources of

acceptable relevant, which can be used for cross-validation.



20

2.2.3 Performance Ratio

The losses experienced in a system are cumulatively combined to give

a Performance Ratio (PR) of the plant which is a measure of both the

performance and the efficiency of the ‘on the ground’ equipment and

systems, and is defined below as:

energyltheoretica

energyrealPR

_

_

=

The PR compares the system Coefficient of Performance (COP) with

benchmark module performance at STC condition, ƞSTC, which can be

defined as:

�� ƞ�

where,

� COP = Ratio of the electric energy, EAC ,from the system divided by

the estimated irradiance to the system’s inclined surface, Gk; and

� ƞSTC = Ratio of nominal PV power, Pnom (kWp), divided by the

irradiance at STC condition, GSTC (1 kW/m2).

Thus,

�� E G� �

�P��G��

The higher the quality of the modules and the system, the higher the

PR. Before a plant becomes operational the PR can be predicted

based on the proposed equipment and design. Typically, PR is

calculated using commercially available software PVsyst and

complemented where necessary with additional modelling.

The PR metric is widely used contractually in order for the construction

contractor to guarantee the plant performance during an agreed period

of time from plant commercial operation.

A step-by-step annual energy output calculation derived from PR and

incident irradiance, for the Lender’s practical use, is attached in

Appendix A.



21

2.2.3.1 Standard Test Conditions (STC)

Performance data given by the PV module manufacturer is only valid

for certain test conditions which are given in Table 2.4. The power

output at STC is known as the nameplate power or installed Watt-peak

(Wp). STC is an international standard to measure module

performance.

Table 2.4: Standard Test Conditions (STC), for PV module output rating

Criteria Condition

Irradiance 1000 W/m2

Spectrum Air Mass (AM) 1.5

Cell Temperature 25°C

Spectrum at STC is represented by the air mass coefficient, which

approximates the change in spectrum of solar radiation given scattering

and absorption as light waves travel through the atmosphere. The STC

condition of AM 1.5 represents 1.5 times the optical path length through

the Earth's atmosphere compared to when the sun is at the zenith (i.e.

directly overhead the site location), and is approximately representative

of idealised spectral conditions in the upper latitudes of Southeast Asia.

The actual site conditions at the module surface will differ from the

laboratory conditions (and will also differ continuously throughout the

day and depending on the specific region) and can affect the

performance of the module. It is important to use a consistent

performance indicator benchmarked to STC throughout the industry in

order to make meaningful comparisons.

2.2.3.2 Key losses and Performance Ratio Calculation

The key losses in solar PV project can be broadly categorized into two

types of losses which are:

� Capture losses; and

� System losses;

In brief, capture losses are mainly dependent on the quality of

equipment and its properties performing under the site conditions

together with the design of the plant. While the system losses will

mainly depend on plant design.

Key losses considered for PR calculation are shown in Table 2.5 below.



22

Table 2.5: Key losses for PR calculation

Type of Losses (Annual) Typical Annual Average Losses in Percentage Terms (in SEA)

Capture losses

Spectral 1% loss to 1% gain

Shading 1 – 5% loss

Soiling (e.g. dust) 1 – 2% loss

Angular 1 – 3.5% loss

Low irradiance performance 3.5% loss to 2% gain

Temperature losses 4 – 12% loss

Power Tolerance 3% loss to 2% gain

Light-induced degradation (LID) 1 – 2% loss

Mismatch 0 – 3% loss

System losses

DC and AC cabling 1 – 4% loss

Inverter curtailment 0 – 4% loss

AC/DC performance of Inverter 1 – 4% loss

Transformers 1 – 2% loss

Availability 0 – 2% loss

From Table 2.5 it can be seen that the PR is highly dependent on

module temperature. The efficiency of PV cells decreases at a rate of

approximately 0.2 – 0.5 % per °C above STC module temperature of

25°C. Modules can heat up to 70°C, with a higher module temperature

resulting in lower power output. The magnitude of the effect mainly

depends on the local environment, the insulation of the back of the cell

and the specific cell in question. Due to high ambient temperatures

across the majority of SEA, projects located in the region would

typically experience high temperature losses compared to other losses.

An example of PR calculation for solar PV project using crystalline PV

modules is shown in Table 2.6.



23

Table 2.6: Example PR Calculation for a solar PV plant

Type of Losses (Annual) Losses Performance

Spectral 0.5% 99.5%

Shading 1.7% 97.8%

Angular 1.0% 96.8%

Low irradiance performance 2.5% 94.4%

Temperature losses 9.2% 85.7%

Mismatch 0.5% 85.3%

Power tolerance 0.0% 85.3%

Light-induced degradation (LID) 1.5% 84.0%

DC wiring losses 0.3% 83.8%

MPPT performance 0.5% 83.3%

AC/DC performance of Inverter 2.4% 81.3%

AC wiring losses 0.5% 80.9%

AC transformers 1.2% 80.0%

Availability 1.0% 79.2%

Soiling 1.0% 78.4%

Example Initial Annualised PR 78.4%

Generally the initial operating PR for a solar PV system in SEA with

good design and equipment quality would be in the approximate range

of 75 – 85%.

2.2.3.3 Energy yield and revenue calculation

Revenue of a solar PV project can be calculated based on the energy

production from the solar PV system.

The energy production is estimated from:

� Project installed capacity;

� Solar irradiance; and

� Project PR in each operating year.

Specific yield

For a solar PV plant, specific yield is generally used to determine the

plant’s energy production capability per unit installed capacity

(kWh/kWp). The specific yield is simply the product of the irradiance

and the initial annualised PR of the project. The specific yield is usually

calculated based on monthly data and summed to give an estimated

annual specific yield. For the annual energy prediction over a project’s

life, the PR in each respective operating year is used.



24

The specific yield is a useful parameter to compare solar PV system

performance.

For instance, if the plant annual plant PR and annual irradiance are:

Project A

� Annual Plant PR: 75.0%

� Annual Irradiance: 1,700 kWh/m2

Project B

� Annual Plant PR: 80.0%

� Annual Irradiance: 1,500 kWh/m2

The annual specific yield of Project A and Project B are therefore:

� Project A: 1,275 kWh/kWp/year

� Project B: 1,200 kWh/kWp/year

It can be seen that although the PR of Project A is lower the specific

yield is still higher compared to Project B due to high irradiance

conditions manifested for Project A. Both annual PR and annual

irradiance parameters are therefore necessary for determining energy

production of a given project.

Energy yield calculation

An energy yield calculation is finally derived based on the product of

specific yield and total plant installed capacity.

PV module performance degradation over time also needs to be

considered when calculating annual energy production of a solar PV

project. Typically, a PV module manufacturer will provide a degradation

warranty to ensure that PV module performance will not degrade

beyond certain magnitude.

Assuming the inputs below for Project A:

� Initial Installed capacity: 5,000 kWp

� Annual degradation rate: 0.6% per year

� Project life: 5 years

Project A’s energy production for an illustrative 5 years of operation is

calculated and shown in Table 2.7.



25

Table 2.7: Example for energy yield calculation of solar PV project

Operational Year

Initial Specific Yield (kWh/kWp/year)

Initial Installed Capacity (kWp)

Effective Installed Capacity after

Degradation (kWp) Energy Estimate

(MWh/year)

1 1,275 5,000 4,985 6,356

2 1,275 5,000 4,955 6,318

3 1,275 5,000 4,925 6,280

4 1,275 5,000 4,896 6,242

5 1,275 5,000 4,866 6,205

It can be seen that the energy production will decrease each year due

to the annual degradation performance of PV module.

As already noted, a step-by-step annual energy output calculation

derived from PR and incident irradiance, for the Lender’s practical use,

is attached in Appendix A.

Recommended energy yield results for Lenders

Energy yield estimation inherits uncertainties from various parameters

such as irradiance data, modelling, and variations of irradiance over a

project’s life.

The probability of achieving a given energy yield is represented by

a P number. The probabilities are reached by considering project

specific uncertainties and the whole range of exceedance probabilities

of the solar PV plant’s annual energy production. P75 is the annual

energy production which is reached with a probability of exceedance of

75%. In other words, the risk that an annual energy production of P75

is not reached is 25%.

Choice of the P75, P90 or other P value for the base case scenario in

the financial model depends on the risk appetite of the Lenders,

although use of the P90 value is more typically seen in international

project finance transactions.

Assuming the total uncertainty for energy yield estimation is 5% (over

the return period of interest), the total plant energy production for every

year of operation with P50, P75, P90, and P99 for Project A is outlined

in Table 2.8. These results would usually be presented for several

different return periods (e.g. 1 year, 10 years etc), with uncertainty

reducing for longer return periods. For example, P90 yield over a 10

year return period might be used to assess project viability for debt



26

financing, and P90 yield over a 1 year return period for structuring

planned yearly loan repayments.

The P50 and P99 are usually recommended as upside and downside

sensitivity cases, respectively.

Table 2.8: Example for P50, P75, P90, and P99 energy yield calculation of a solar PV project

Operational Year P50 P75 P90 P99

1 6,356 6,160 5,967 5,633

2 6,318 6,123 5,931 5,600

3 6,280 6,086 5,895 5,566

4 6,242 6,050 5,860 5,533

5 6,205 6,013 5,825 5,499

Revenue calculation

Project revenue can be calculated based on the agreed value stated in

the Power Purchase Agreement (PPA).

Revenue of Project A for P50, P75, P90, P99 are outlined in Table 2.9,

assuming the example of the PPA states that the relevant party will

purchase the energy from Project A based on an illustrative 5 year

Feed-in-Tariff scheme with the fixed-rate of 0.20 USD/kWh. The

Lenders would use these generated revenues as inputs into the

financial model, based on the actual project lifetime or loan term

duration.

Table 2.9: Example of P50, P75, P90, and P99 revenue calculation of solar PV project

Operational Year P50 P75 P90 P99

1 1,271,200 1,232,000 1,193,400 1,126,600

2 1,263,600 1,224,600 1,186,200 1,120,000

3 1,256,000 1,217,200 1,179,000 1,113,200

4 1,248,400 1,210,000 1,172,000 1,106,600

5 1,241,000 1,202,600 1,165,000 1,099,800



27

2.3 Cost structure of a solar PV project in the region

It is important for Lenders to understand whether the solar PV project to

be financed can be considered expensive for the given technology and

design proposed. In order to support the understanding of key cost

drivers of a solar PV project, an approximate cost breakdown for solar

PV plants, based on international and regional experience, is provided

in Table 2.10. It should be noted that the cost of solar PV panels and

equipment has changed significantly during recent years and there may

be project specific issues which also need to be considered to confirm

the reasonableness of the project costs for any given project.

Table 2.10: Typical cost breakdown for a solar PV project, SEA, 2014

Items USD/Wp % Portion with

respect to CAPEX

CAPEX 1.70 – 2.40

EPC 1.50 – 2.00 80 – 90

PV modules 0.60 – 0.80 25 – 40

Inverters 0.15 – 0.35 5 – 15

Foundation and Mounting structures 0.15 – 0.35 5 – 15

Balance of Plant (BoP)

including civil and electrical equipment and installation works

0.30 – 0.60 15 – 35

Non-EPC (Development, financial, contingencies, etc. but excluding land costs)

0.20 – 0.40 10 – 20

OPEX per year (O&M fee, land lease, insurance, etc.)

0.03 – 0.06



28

Having provided an introductory background to solar PV project

technology, yield assessment and typical costs, the subsequent focus

of these Lending Guidelines is on techno-commercial risk mitigation

under non-recourse project finance solar PV projects.

Project finance can be defined as the financing of infrastructure projects

with an upfront spend element in a way that removes recourse by the

Lenders to the Sponsors (non-recourse financing), or limits such

recourse (limited recourse financing). In such projects the sole security

of the Lenders is the revenue stream and assets of the project.

Project finance projects are highly structured deals that move liabilities

off Sponsor’s balance sheet and bound and contain the risk in the

project vehicle company. In project finance deals banks negotiate at

the micro level and well defined are placed liabilities on contracting

parties to ensure delivery of revenue stream. Project risks need to be

clearly allocated, understood and bounded. Project risks are therefore

assessed and managed and/or mitigated (when possible) by the project

stakeholders that are best placed to do so.

The following section provides a set of due diligence checklists

highlighting common key techno-commercial risks throughout the

project lifecycle, emphasizing benchmarks and factors to consider, risk

management and mitigation actions, and project stakeholders that

should ordinarily be best placed to manage and mitigate such risks.

The due diligence checklist is provided for the following project risk

areas typical of both power projects in general, and solar PV power

projects in particular:

� Technology risks (e.g. underperformance, warranty coverage);

� Design and construction risks (e.g. delay, cost overrun,

underperformance);

� Performance projection risks (e.g. underperformance);

� Operation risks (e.g. plant unavailability, lack of cost control); and

� Contractual risks (e.g. delay, cost overrun).

3 Risk management and mitigation under project finance



29

4.1 Overview

This section highlights common technical risks throughout the project

cycle and offers advice on how to manage and/or mitigate them. The

list of risks given in the following sections should not be considered

exhaustive. Each project will have some unique risks that need to be

identified and mitigated.

It should also be noted that no environmental and permitting risks,

which are mostly country-specific, are included in these Lending

Guidelines.

4.2 Key technology risks

Table 4.1: Key technology risks and risk management/mitigation actions

Due Diligence Item

Factors to consider/check Benchmark

Risk management/mitigation actions Party involvement

Proven Technology

PV module bankability

Model track-record of at least of 100 MW in operation, preferably within

non-recourse project financed

utility-scale plants

Assess PV module technology bankability including:

PV module specifications

IEC certifications held by module model proposed

ISO certifications held by manufacturing facility

Laboratory based performance testing

Request Original Equipment Manufacturer (OEM) support

Request for OEM insurance

If insufficient track record, commission a PV module

bankability report undertaken by an independent third party

focusing on module manufacturing quality, testing

and operating performance

PV module manufacturer/supplier

Insurance company

Independent technical advisor

Inverter bankability

Inverter model track-record of

100 MW at operational

availability of minimum 98% and rated efficiency of

more than 95%

Appropriate “ingress protection”

(IPxx) rating for installation

environment

International certifications held

Check against approved inverter list from the grid owner if

applicable

Request laboratory test reports to support compliance with the

most recent national grid-tied inverter requirements

If insufficient track record, commission a third party review of manufacturing quality, testing

and operating performance

Inverter manufacturer/supplier

Insurance company


4 Due diligence checklists



30

Due Diligence Item


Risk management/mitigation actions Party involvement

Warranty terms PV Module: 10 year product

warranty and 25 year performance

warranty

Inverter : 5-10 years product

warranty

Ensure robustness of warranty terms: particular attention should be given to definition of a defect;

scope of cost coverage; and testing basis for a performance

warranty claim

Equipment manufacturer/supplier

Technology Sustainability

Suitability for conditions in SEA

(high humidity and

temperature)

Model track-record of 100 MW in

similar weather conditions

Damp heat tests 1,000 hrs as a

minimum, or 2,000 hrs for high

humidity conditions

Testing against “potential induced

degradation” (PID)

Check track record, operational data, specifications, and

certifications for high humidity and temperature conditions.

Request for OEM support

Request for OEM insurance


Insurance company


Capacity of local O&M service delivery

Review:

manufacturer track record team

/company structure and service in the

region

Track record of 100 MW in the

region

Active service presence in the

country

Ensure equipment suppliers have good track record and after

sales service in region

Inverter supplier provide maintenance teams capable of

carrying out the full usual range of on-site repairs in region

The inverter supplier contractually commits to twenty-

four hour response time


4.3 Design and construction risks

Table 4.2: Key design and construction risks and risk management/mitigation actions

Due Diligence Item

Factors to consider/check Benchmark Risk Management/Mitigation Actions Party Involvement

Site suitability Ground conditions

Ground conditions to

support 25 years of

design life

Ensure that a geo-technical assessment (clay, rock, porosity, stability) is undertaken

to confirm ground stability and ability to support the solar PV installation

Ensure slope stabilization and good drainage if applicable

Independent geotechnical advisor


Flooding risk 50 cm above the maximum historical

flood level

For sites with risk of flooding:

Flood mitigation design in place referenced to robust maximum historical flood level,

with adequate return period (e.g. 50 years)

Take flood insurance

Hydrologist

Project developer/ owner


Earthquake risk n/a Foundation design is sufficiently robust Geologist



31

Due Diligence Item


under earthquake conditions

Take earthquake insurance

Project developer/ owner


Logistics n/a Undertake site visit to ensure site access, ingress/egress, and that transportation

routes (roads, ports, etc.) are suitable for transportation of heavy equipment

(excavators, modules, etc.)

Project developer/owner

Design and construction contractor

Infrastructure required to make

power plant operational

n/a Ensure that all supporting infrastructure to be built by the project developer is scoped, interfaces between works contracts clearly

defined and costs included in the project budget (especially transmission lines,

transformers, etc.), with appropriate contingency reserves for overruns




Construction Contractor capability

Construction contractor

company & team track record and

capability

Sponsor capability to

supervise

n/a Contracting an experienced Construction contractor providing experienced design

and team

In particular for the case where multiple construction contractors will be involved,

with works interfaces to be managed, then a capable Sponsor site team is also important

Construction Contractor

Project Sponsor

Adequate foundations and mounting structure

Foundations and mounting

structure design, geo-technical

conditions

Design for 25 years of design life

Adequate foundations and mounting structure design for site geo-technical

conditions and loading conditions



Adequate design and selection of electrical components

Size and compatibility of

electrical components

1:1.10 – 1:1.25

(DC:AC ratio)

Ensure that inverter size matches with module capacity (Wp)

Transformer and cable sizing do not lead to unusual loss levels (refer to Table 2.5)

Designer and construction contractor


Equipment specification

n/a Ensure specifications comply with international and local standards and

requirements (see section 2 for illustrative international standards on key equipment)



Grid code compliance

Confirm ability of the project to meet relevant

grid code

n/a Ensure that the design meets the grid code, that the contractor has experience meeting grid operator commissioning requirements,

and that commissioning in line with grid code is a contractor obligation



Grid utility

Prevent load shedding and curtailment (when possible)

Grid connection conditions

Plant dispatchability

Plant design

n/a Commission dispatch studies by the utility to confirm plant ability to deliver power (and

dispatchability) at the connection point

Independent verification by a third party of plant ability to deliver power (and

dispatchability) at the connection point



Grid utility

Procurement constraints

Procurement of long lead-time

n/a Confirm schedule for procurement of long-lead items/equipment such as High Voltage

Equipment Supplier

Project Owner



32

Due Diligence Item


and project delays

items (HV) transformer as early as possible, which might for example be 12 months

4.4 Performance projection risks

Table 4.3: Key performance risks and risk management/mitigation actions

Due Diligence Item


Risk Management/Mitigation Actions Party Involvement

Predict solar irradiation with low uncertainty when possible

Availability and quality of solar irradiation

data

n/a Check historical data

If using satellite data, then ensure that the data source has been

successfully validated under similar conditions to the site in the region

Account appropriately for data source uncertainty

Ideally, set up a site meteorological station to validate satellite data

Optimized utilization and correlation of terrestrial and satellite information

Independent energy yield assessor



Adequate energy yield modelling and prediction

Modelling methodologies

Use standard internationally

accepted software (e.g.

PVSyst)

Undertake an independent energy yield assessment using

internationally accepted modelling standards




PR and de-rating factor

PR: 75% – 85%

1st year de- rating factor:

0.6%-2.0%

Subsequent year de-

rating factor: 0.5%-0.8%

Improve PR performance through optimal project design and

technology selection

Use data on degradation from manufacturer lab and operational

data




Module supplier/manufacturer

Input data for modelling/calculating

plant performance

n/a Use of optimal data sources

Develop and derive critical data before modelling and undertake checking against laboratory and

operating data




Soiling n/a Undertake site visit to assess potential current and future sources

of dust from nearby construction, industry, traffic (e.g. on gravel





33

Due Diligence Item



roads), or agriculture (e.g. harvesting, crop burning)

Include sufficient project budget for PV module cleaning if required

Ensure performance warranties clearly define soiling risk ownership


Grid availability Availability 98.5-100%

Understand potential risks of grid outage and load shedding by the

utility (reducing project power sales) in advance by undertaking a

dispatch studies and load analysis



Off-taker Utility

Shading Buildings, structures and trees with

potential to cast shadows on modules

during operation

1 – 5% shading

losses

Undertake site visit to check the real condition

Assess the possibility of buildings/structures/trees to be

erected in vicinity of the PV plant Ensure that shading is considered in

performance calculation (if applicable)



4.5 Operation risks

Table 4.4: Key operation risks and risk management/mitigation actions

Due Diligence Item



O&M contractor capability

O&M contractor and operations

team track record and capability

n/a Contracting an experienced O&M contractor with

experienced O&M team

O&M Contractor


Adequate plant performance monitoring

Existence and quality of

performance monitoring system

How the plant performance will

be monitored, and by which party

n/a Set up an intelligent system for plant monitoring of performance

to monitor variables including accurate irradiance, DC and AC

power output & voltage control

Plant performance optimization with skilled O&M teams with the aim to maintain PR between 75

– 80%, before degradation

Optimal cleaning regime

O&M Contractor

Project developer


Adequate plant availability

Effective operational hours

of the solar PV plant

Availability between 98.0%

- 100.0%

Effective service availability (e.g. module, inverter)

Proactive and responsive maintenance

O&M Contractor


O&M cost control Probability of O&M cost overrun

Common annual O&M

costs: 20-30 USD/kWp

Effective O&M planning and cost control

Budget for maintenance reserve accounts

O&M Contractor


Robust O&M Preventive and n/a Adequate preventive and O&M Contractor



34

Due Diligence Item



Scheme corrective maintenance

scheme

corrective maintenance scheme in place clearly illustrated in the

O&M manual


Sufficient spare parts availability

Availability of the spare parts at the site, or at a depot

in the region

PV module spares: 0.1%-

0.2% of total installed

Inverter spares per supplier

standard

Maintain strategic spare parts on site, or at an in-region depot

O&M Contractor


4.6 Contractual risks

Table 4.5: Key contractual risks and risk management/mitigation actions

Due Diligence Item



PPA technical risks

Clauses in PPA for RE generators (esp. Solar

PV):

- Is there any compensation in the

event of grid outage? : Force Majeure for

“interruptions in the distribution system…”

Any performance requirements (energy

production, construction completion,

commissioning requirements, etc)

n/a Given standardised forms of PPA, no project level risk

mitigation actions are usually possible

At national level; improve strength of “priority dispatch”

terms for renewable generators

Improve information from off-taker regarding grid

reinforcement and load flow scenarios

Government

Industry associations

Off taker


Multi-contract versus EPC versus risk

Contract structure and risk allocation

Uncovered risks

n/a Ensure EPC wrap-up when possible, and if not, ensure well-

structured multi-contract approach with experienced

management of works interfaces

Consider owner’s engineer

Construction contractor


Owner’s engineer

Contractor capability (EPC, O&M, others)

Contractor track record n/a Ensure contractor track record and team capability

EPC contractor

Project Owner

Cost overrun Cost overrun (EPC and Operations) by multiple

factors

Contingencies: more than 3% of EPC

cost depending on project factors

Allocate reasonable contingencies following robust project development, design , construction and procurement

Follow EPC wrap contract approach when possible, with

major risks including geotechnical risk allocated to the EPC

contractor

Establish maintenance reserve

EPC contractor

O&M contractor


Lender



35

Due Diligence Item



accounts depending on inverter warranties

Run financial model sensitivities

Robust EPC contract terms

Scope of work is a lump sum turnkey scope

n/a Identify EPC scope and ensure that it is inclusive and wrapped

under lump sump

EPC contractor


Owner’s engineer

Owner’s obligation to the Project

n/a Clearly identify any responsibilities that might require

consents or actions from the owner in order to allow the

contractor to perform the work adequately

EPC contractor


Owner’s engineer

Key project milestones n/a Key project milestones, in particular for completion, shall clearly be implemented in the

EPC contract

EPC contractor


Owner’s engineer

Defect warranty for material and

workmanship

Minimum of 2 years

Warranty scope and terms clearly defined in the EPC contract

Warranty obligations backed by financial security (e.g.

performance bond) if appropriate

EPC contractor


Owner’s engineer

Performance Guarantee PR guarantee prior to plant

take over

PR guarantee for the first 2-5

operation years

Guarantee terms clearly defined in the employer requirements and

EPC contract

PR test methodology to follow good industry practice

EPC contractor


Owner’s engineer

Liquidated Damages n/a Clearly defined rates and caps for liquidated damages for both

delay and performance shortfalls stated within the EPC contract.

In line with good industry practice

EPC contractor


Owner’s engineer

Testing and Commissioning

In accordance with IEC

62446

Clearly defined in the employer requirements and EPC contract

In line with PPA and grid code requirements

EPC contractor


Owner’s engineer

Robust O&M terms

Scope of work n/a Ensure inclusive O&M scope (e.g. site staff; preventative,

routine, and reactive maintenance; spare parts

supply/storage; site security etc)

O&M contractor


Contract Duration 5 years as a minimum

Clearly defined in the O&M contract

O&M contractor


Plant Availability Guarantee

A minimum of 98% plant availability guarantee

Compensation equivalent to foregone revenue for a shortfall in

plant availability guarantee, capped at 100% of annual O&M

fee

O&M contractor




36

Appendices

Appendix A. Detailed Annual Energy Output Calculation Derivation ______________________________________ 37



37

�� !!"�# $�"�#�!�%&'�"�("�)*�+%��$�#�!�%&'�"�("�,��-)��+!��+!.

�� !!"�# $�"�#�!�%&'�"�("� � �� / )*�+%��$�# !!"�#�!�%&'�"�("�,��-)��+!��+!.

Whereas,

Theoretical Energy Output (at STC Condition) is calculated by ratio method below.

At STC Condition, the power output is Pnom W (the power output stated in the module specification multiplied

by the total number of installed module in the plant). So in order to find the theoretical energy (at STC

condition) given the irradiance condition at the site, the following ratio method is used:

1 kW/m2 (STC Condition) Pnom kW

Annual Incident Irradiance kWh/m2

00123405678094::2762058;�<=/?@A/B0C?,�<.D,EF �@⁄ .

(irradiance condition at the site)

Therefore,

)*�+%��$�# !!"�#�!�%&'�"�("�,��-)��+!��+!. � AnnualIncidentIrradiance,kWh/mX. / Pnom,kW.1,[\ �X⁄ .

� AnnualIncidentIrradiance / Pnom,kWh.

Hence,

�� !!"�# $�"�#�!�%&'�"�("� � �� / AnnualIncidentIrradiance / Pnom,kWh.

Please note that the linear degradation has not included in the PR (except for light-induced degradation),

however it should be included in the estimated annual actual energy output calculation, therefore.

�� !!"�# $�"�#�!�%&'�"�("�� / AnnualIncidentIrradiance / Pnom / AnnualLinearDegradation,kWh.

Appendix A. Detailed Annual Energy Output Calculation Derivation



38

AC Alternating Current

ACE ASEAN Centre for Energy

AMS ASEAN Member States

ASEAN Association of Southeast Asian Nations

ASEAN-RESP Renewable Energy Support Programme for ASEAN

a-Si Amorphous Silicon

CAPEX Capital Expenditure

CdTe Cadmium Telluride

CIGS Copper Indium Gallium Selenide

COD Commercial Operation Date

DC Direct Current

EPC Engineering, Procurement and Construction

GIZ Deutsche Gesellschaft für Internationale Zusammenarbeit

HV High Voltage

Hz Hertz

Km Kilometre

kV Kilovolt

kVA Kilovolt-Ampere

kW Kilowatt

kWh Unit of electrical energy in kilowatt hour

LV Low Voltage

LTA Lender’s Technical Advisor

m MSL Meters above mean sea level

MM Mott MacDonald

MPPT Maximum Power Point Tracking

MW Megawatt

MWp Megawatt Peak (Rated DC capacity at STC), see Wp below

MV Medium Voltage

OEM Original Equipment Manufacturer

Glossary



39

O&M Operation and Maintenance

OPEX Operation Expenditure

P50 The expected net energy production at probability of 50%



PID Potential Induced Degradation

PPA Power Purchase Agreement

PR Performance Ratio

PV Photovoltaic

RE Renewable Energy

SEA Southeast Asia

STC Standard Test Conditions, for testing Solar PV modules

W Watts

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